Oxidative internal breaker system with breaking activators for viscoelastic surfactant fluids

ABSTRACT

Compositions and methods are given for delayed breaking of viscoelastic surfactant gels inside formation pores, particularly for use in hydraulic fracturing. Breaking inside formation pores is accomplished without mechanical intervention or use of a second fluid. Bromate oxidizing agents are used along with selected breaking activators for the bromate breaking compounds. Useful bromate breaking activators include acid-generating breaking activators, oxidizing sulfur containing breaking activators, and reducing agent breaking activators.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application a continuation-in-part of application Ser. No. 11/532,565, entitled “Oxidative Internal Breaker for Viscoelastic Surfactant Fluids”, filed Sep. 18, 2006 now U.S. Pat. No. 7,879,770. This application is related to copending application Ser. No. 11/532,553, entitled “Internal Breaker for Oilfield Treatments,” inventors Jesse Lee, Philip Sullivan, Erik Nelson, Yiyan Chen, Carlos Abad, Belgin Baser, and Lijun Lin, filed Sep. 18, 2006. This application is related to copending application Ser. No. 11/532,559, entitled “Internal Breaker for Oilfield Fluids,” inventors Philip Sullivan, Yiyan Chen, Belgin Baser, Carlos Abad, Mehmet Parlar, and Gregory Kubala, filed Sep. 18, 2006. This application is also related to copending application Ser. No. 11/532,705, entitled “Method for Limiting Leakoff and Damage in Hydraulic Fractures,” inventors Richard Hutchins, Marie Dessinges, and Carlos Abad, filed Sep. 18, 2006. These applications are all assigned to the assignee of the present application and are hereby incorporated in their entirety.

BACKGROUND OF THE INVENTION

The invention relates to recovery of oil and gas from wells, and more particularly to breaking fluids inside formation pores when using viscoelastic surfactant fluid systems (VES's) as carrier fluids and treatment fluids.

There are many applications in which breakers are needed to decrease the viscosity of treatment fluids, such as fracturing, gravel packing, and acidizing fluids, viscosified with polymers or crosslinked polymers or viscoelastic surfactants. Most commonly, these breakers act in fluids that are in gravel packs or fractures; some breakers can work in fluids in formation pores. Breakers decrease viscosity by degrading polymers or crosslinks when the viscosifiers are polymers or crosslinked polymers. Breakers decrease viscosity by degrading surfactants or destroying micelles when viscosifiers are viscoelastic surfactant fluid systems. Most breakers are solids, for example granules or encapsulated materials, that do not enter the formation.

There is sometimes a need to break viscous fluids within the pores of formations, for example when viscous fluids enter formations during fracturing, gravel packing, acidizing, matrix dissolution, lost circulation treatments, scale squeezes, and the like. Breakers that are effective inside formations will be called internal breakers here. These fluids that enter the formation may be main treatment fluids (such as fracturing fluids) or they may be secondary fluids (such as flushes or diversion fluids such as viscoelastic diverting acids). Typically it is necessary that the break be delayed, that is that the breaker not act until after the fluid has performed its function.

The current practice to improve clean-up of VES fluids in matrices is to use pre-flush or post-flush fluids to dilute the system or to contact the system with a breaker. The major disadvantage of the use pre-flush or post-flush fluids is their limited interaction with the VES fluid due to the small interface between the two fluids. The efficiency of this breaking mechanism depends upon diffusion, which is slow in highly viscous fluids. Furthermore, the volumes of the flushes can be high.

Compositions and treatment methods using a delayed internal breaker, that acts without mechanical or chemical action by the operator, would be of value. It would be desirable to have a number of such materials so that they could be used under different subterranean conditions, for example different temperatures and different formation fluid chemistries.

It has now been discovered that certain oxidizing internal breakers, when combined with selected breaking activators will allow fluid design with pre-selectable timing for breaking of the fluid, and will also allow breaking of the fluid to occur at lower temperatures.

SUMMARY OF THE INVENTION

The composition of the invention is an oilfield treatment composition containing an aqueous fluid, a non-polymeric viscosifier and an oxidizing agent selected, for example, from peroxysulfuric acid, a peroxymonosulfuric acid salt, persulfates, peroxides, hydroperoxides, azo compounds, peracids, perborates, peresters, bromates, iodates, periodates, permanganates, chlorites, and hyperchlorites. The composition may optionally include a free radical propagating agent, for example ferrous ions, metabisulfites, reducing sugars, and reducing di-, tri-, oligo- and poly-saccharides. The composition may optionally include an oxygen scavenger, for example sulfites, furanones, hydroxylamines, trivalent phosphorous compounds, phenolic antioxidants, thiosulfates, metabisulfites, hydrazines, carbohydrazides, hydroquinones, and erythorbates.

In one embodiment, the composition comprises a combination of a bromate salt breaker and a breaking activator for the bromate salt. Useful breaking activators include acid-generating breaking activators, sulfur containing breaking activators and reducing agent breaking activators. Surprisingly, such breaking activator activates a bromate salt even though it may delay other internal oxidizative breakers; i.e., the combination of the bromate salt and the breaking activator produces a synergistic effect allowing breaking at lower temperatures, and allowing fine tuning of the timing of the break, or a “selectable” breaking time. The bromate salt breaker may be selected from salts of bromates such as sodium bromate and potassium bromate.

In one embodiment, the breaking activator for the bromate is selected from aldehydes, oxidizing or reducing sulfur-containing compounds, preferably persulfate or thiosulfate compounds such as sodium thiosulfate or potassium thiosulfate, and sodium persulfate.

In another embodiment, the breaking activator may be selected from persulfates or thiosulfates.

In another embodiment, the breaking activator is sodium thiosulfate or sodium persulfate.

In another embodiment, the breaking activator is selected from glutaraldehyde and glucose.

In yet another embodiment, the non-polymeric viscosifier is a viscoelastic surfactant, for example a zwitterionic surfactant, for example a betaine, or an amidoamine oxide.

In yet another embodiment the fluid pH can be buffered to control the break time

Another embodiment of the invention is a method of treating a subterranean formation penetrated by a wellbore comprising a) injecting into the pores of the formation an aqueous gel comprising a non-polymeric viscosifier, a bromate oxidizing agent soluble in the gel, and a breaking activator for said bromate oxidizing agent, and b) allowing said gel to lose viscosity in the pores after the injection.

Another embodiment is a method of treating a subterranean formation penetrated by a wellbore comprising a) injecting into the pores of the formation an aqueous gel comprising a non-polymeric viscosifier, a bromate oxidizing agent soluble in the gel, and a breaking activator for said bromate oxidizing agent, wherein said breaking activator is selected from the group consisting of acid-generating breaking activators, oxidizing or reducing sulfur containing breaking activators, and reducing agent breaking activators, and b) allowing said gel to lose viscosity in the pores after the injection.

Another embodiment is a method of treating a subterranean formation penetrated by a wellbore comprising a) injecting into the pores of the formation an aqueous gel comprising a non-polymeric viscosifier, a bromate oxidizing agent soluble in the gel, and a breaking activator for said bromate oxidizing agent, wherein said breaking activator is selected from the group consisting of persulfates, thiosulfates, thiosulfites, dithionites, dithionates, tetrathionates, hyposulfites, and aldehydes, and b) allowing said gel to lose viscosity in the pores after the injection.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows the viscosity vs. time of a) a base VES fluid in 2 wt % KCl; (b) the VES fluid with either 1 wt % sodium bromate or 1 wt % sodium thiosulfate pentahydrate; and (c) the VES fluid with 1 wt % sodium bromate and 2 wt % or 0.5 wt % sodium thiosulfate pentahydrate at 93.3° C. (200° F.).

FIG. 2 shows the viscosity vs. shear rate of a VES fluid containing sodium bromate and sodium thiosulfate pentahydrate at 93.3° C. (200° F.).

FIG. 3 shows the viscosity vs. time of the base VES fluid containing 4 vol % BET-E-40, 2 wt % KCl, 1 vol % 2-butoxyethanol, (a) with no other additive; (b) with 1 wt % sodium bromate and 2 wt % sodium thiosulfate pentahydrate at 79.4° C. (175° F.).

FIG. 4 shows the viscosity vs. time for VES fluids containing 8 vol % BET-E-40 in 1.427 g/mL (11.9 lbm/gal) sodium bromide brine, (a) with no other additive; (b) with either 1 wt % sodium bromate or 1 wt % sodium thiosulfate pentahydrate; and (c) with 1% sodium bromate and 2 wt % sodium thiosulfate pentahydrate at 93.3° C. (200° F.).

FIG. 5 shows the viscosity as a function of shear rate for a VES fluid containing 8 vol % BET-E-40, 1 wt % sodium bromate and 2 wt % sodium thiosulfate pentahydrate in 1.427 g/mL (11.9 lbm/gal) sodium bromide brine at 93.3° C. (200° F.).

FIG. 6 shows the viscosity as a function of time at for VES fluids containing 6 vol % BET-E-40 in 1.391 g/mL (11.6 lbm/gal) calcium chloride brine, (a) with no other additive; (b) with 1 wt % sodium bromate; and (c) with 1 wt % sodium bromate and 2 wt % sodium thiosulfate pentahydrate at 93.3° C. (200° F.).

FIG. 7 shows the viscosity as a function of time for VES fluids containing 6 vol % BET-E-40 in 2 wt % KCl brine, (a) with no other additive; (b) with either 1 wt % potassium bromate or 2 wt % sodium thiosulfate pentahydrate; and (c) with 1 wt % potassium bromate and 2 wt % sodium thiosulfate pentahydrate at 93.3° C. (200° F.).

FIG. 8 shows the viscosity as a function of time for VES fluids containing 6 vol % BET-E-40, 1 wt % sodium bromate, and (a) 0.5% glutaraldehyde in 2 wt % KCl brine at 93.3° C. (200° F.); (b) 0.5% glutaraldehyde in 2 wt % KCl brine 107.2° C. (225° F.); and (c) 0.75% glutaraldehyde in 1.427 g/mL (11.9 lbm/gal) NaBr brine at 98.9° C. (210° F.).

FIG. 9 shows the viscosity as a function of time for a VES fluid containing 6 vol % BET-E-40, 2 wt % KCl, 1 wt % sodium bromate, and 0.2 wt % sodium persulfate at 93.3° C. (200° F.).

FIG. 10 shows the viscosity as a function of time for VES fluids containing 6 vol % BET-E-40, 2 wt % KCl, 0.5 wt % sodium bromate, and (a) 0.25 wt % sodium tetrathionate dihydrate; (b) 0.5% wt % sodium tetrathionate dehydrate at 93.3° C. (200° F.).

FIG. 11 shows the viscosity as a function of time for a VES fluid containing 6 vol % BET-E-40, 2 wt % KCl, 1 wt % sodium bromate and 1 wt % ammonium chloride at 93.3° C. (200° F.).

FIG. 12 shows the viscosity as a function of time for a VES fluid containing 6 vol % BET-E-40, 2 wt % KCl, 1 wt % sodium bromate, and 1 vol % tetraethylenepentamine at 93.3° C. (200° F.).

FIG. 13 shows the viscosity as a function of time for VES fluid containing 6 vol % BET-E-40, 2 wt % KCl, 1 wt % sodium bromate, and 2 wt % glucose at 107.2° C. (225° F.).

FIG. 14 shows the viscosity as a function of time for VES fluids containing 6 vol % BET-E-40, 2 wt % KCl, and 2 wt % glucose at 107.2° C. (225° F.).

FIG. 15 shows the viscosity as a function of time for VES fluid containing 6 vol % BET-E-40, 2 wt % KCl, 0.5 wt % sodium bromate, and 0.1 wt % sodium bisulfite at 93.3° C. (200° F.).

FIG. 16 shows the viscosity as a function of time for VES fluid in 1.427 g/mL (11.9 lbm/gal) NaBr brine containing 6.5 vol % BET-E-40, 0.2 vol % 2-butoxyethanol, 1 wt % sodium bromate, and 0.1 wt % sodium bisulfite at 103.9° C. (219° F.).

DETAILED DESCRIPTION OF THE INVENTION

For viscosified fluids used in oilfield treatments, it is important that there be a mechanism by which the viscosity can be reduced (that is, the fluid can be broken). Typically, breakers are added to the fluid. Typically, the action of the breaker is delayed or requires a trigger such as crushing of encapsulated breakers, so that the fluid may perform its function before the break occurs. Proper placement is an important feature for any breaker; it must be with the fluid that is to be broken. Once a fluid invades a formation, most conventional breakers (such as encapsulated oxidizing agents) cannot clean it up. Subsequently adding another fluid, such as an acid, will be inefficient because of the poor fluid-to-fluid contact.

Oxidizing agents have been tried in the past as breakers for fluids viscosified with non-polymeric viscosifying agents, but without success. U.S. Patent Application No. 2006-0041028 describes metal-mediated viscosity reduction of viscoelastic surfactant fluids and states in paragraph [0007] that “Conventional enzymes and oxidizers have not been found to act and degrade the surfactant molecules or the viscous micelle structures they form.” U.S. Patent Application No. 2005-0037928 “Method of Using Viscoelastic Vesicular Fluids to Enhance Productivity of Formations” discloses vesicular aqueous viscoelastic surfactant based fluids that contain a surfactant, a quaternary amine polyelectrolyte, and a non-aqueous solvent. In the specification, these materials are repeatedly distinguished from fluids made with worm-like micelles, such as those fluids described in U.S. Pat. No. 6,435,277. The application discloses that the vesicular fluids are sensitive to pH and that they can be broken in the presence of acid. It further teaches that they may be broken by oxidative breakers. More specifically, it teaches that oxidizers may be the only added “breaker” when the fluid is used as a diverter of acid treatments because the fluid will come in contact with acid, but in fracturing fluids the oxidative breaker may only be used in combination with acid-releasing agents, and in fact the acid-releasing agents are suitable breakers alone. In contrast to these teachings, we have found that certain compositions containing oxidizing agents may be used as breakers of VES fluids; the oxidizers are readily soluble in the VES fluid, and the break is activated by increasing temperature or by adding a breaking aid.

The invention will be described primarily in terms of hydraulic fracturing, gravel packing, acidizing, and fracture acidizing, although it is to be understood that the invention may be used in many other ways, for example many other oilfield treatments. In hydraulic fracturing, most of the injected fracturing fluid contains a proppant such as sand or synthetic ceramic beads, so that when the pressure is released the proppant is trapped between the fracture faces and prevents the fracture from completely closing, thus leaving a flowpath open. The injected fracturing fluid is normally viscosified. Increased viscosity results in formation of a wider fracture, thus a larger flowpath. A minimal viscosity is also required to transport adequate amounts of proppant; the actual viscosity required depends primarily upon the fluid flow rate and the density of the proppant. In a typical fracturing process, such as hydraulic fracturing with aqueous fluids, the fracture is initiated by first pumping a high viscosity fluid with good to moderate leak-off properties, and typically no proppant, into the formation. This initial fluid, typically referred to as a “pad”, is usually followed by a second fluid (fracturing fluid) of similar viscosity carrying an initially low concentration and then a gradually increasing concentration of proppant into the extended fracture or fractures. The pad initiates and propagates the fracture but does not need to carry proppant. All the fluids tend to “leak-off” into the formation from the fracture being created or extended. Commonly, by the end of the job the entire volume of the pad will have leaked off into the formation. This leak-off is determined and controlled by the properties of the fluid (and additives it may contain, such as fluid loss additives or FLA's), the pumping rate and pressure, and the properties of the rock. A certain amount of leak-off greater than the minimal possible may be desirable, for example a) if the intention is to place some fluid in the rock to change the rock properties or to flow back into the fracture during closure, or b) if the intention is deliberately to cause what is called a “tip screen-out”, or “TSO”, a condition in which the proppant forms a bridge at the some point in the fracture, stopping the lengthening of the fracture and resulting in a subsequent increase in the fracture width. In acid fracturing, the fracture fluid is an acid (or other formation dissolving fluid such as a chelant-containing fluid) and the fluid normally does not contain proppant; the fracture is held open by asperities in the fracture faces caused by differential etching of the formation material. In matrix acidizing, an acid or other formation dissolving fluid is injected below fracture pressure and the fluid enters the formation and dissolves damaging materials and/or a portion of the formation. Proper leak-off control may be critical to the success of these and other oilfield treatments. In these and many other treatment types, after the treatment it is necessary to decrease the viscosity of the fluid, i.e. to break them, and a portion of the fluid in the pores of the formation.

Certain materials may be used as delayed oxidative internal breakers for polymer-free (VES) fluid viscosifiers; the break by the oxidizing agent may be triggered naturally due to chemical or physical conditions, for example temperature or pH. It is well known that the decomposition rate constant of some radical initiators is not only temperature but also pH dependent (See, for example, “Polymer Handbook, Section II, Decomposition Rates of Organic Free Radical Initiators”, J. Brandrup, and E. H. Immergut, Third Edition, Wiley Interscience.) The rate of decomposition may also be altered by appropriately selecting a counterion for the oxidizing agent, (e.g. sodium, potassium, and ammonium). The break may optionally be accelerated by using redox activators, for example sodium metabisulfite, iron (II) sulfate, reducing sugars, for example glucose and others, reducing di and trisaccharides, and reducing oligo and polysaccharides. The break may optionally be delayed, for example by the addition of oxygen scavengers, for example substituted Benzofuranones (for example Ciba Specialty Chemicals lactone HP-136), hydroxylamines, trivalent phosphorus compounds, for example organic phosphites (and phosphonites) such as TNPP, CIBA Specialty Chemicals Irgafox® 168, CIBA Specialty Chemicals, Irgafox® P-EPQ, CIBA Specialty Chemicals, phenolic antioxidants, for example di terbutyl alkyl phenols, and others such as those of the Irganox® family such as IRGANOX® L 115, IRGANOX® L 109, IRGANOX® L 107, IRGANOX® L 1010, IRGANOX® L 1035, IRGANOX® L 1076, IRGANOX® L 1081, IRGANOX® L 1098, IRGANOX® L 1135, IRGANOX® L 1330, IRGANOX® L 3114, IRGANOX® L 245, IRGANOX® L 3114, IRGANOX® B 1411, IRGANOX® B 1412, IRGANOX® B 215, IRGANOX® B 220, IRGANOX® B 225, IRGANOX® B 311, IRGANOX® B 561, IRGANOX® B 612, IRGANOX® B 900, IRGANOX® B 921, IRGANOX® E 201, IRGANOX® E 1291, IRGANOX® HP 2215, IRGANOX® HP 2225, IRGANOX® HP 2251, IRGANOX® HP 2341, IRGANOX® HP 2411, IRGANOX® HP 2921, IRGANOX® MD 1024, IRGANOX® PS 800, IRGANOX® PS 802, IRGANOX® XP 320, IRGANOX® XP 420, and IRGANOX® XP 620, trigonox, sulfur compounds such as sodium thiosulfate, hydroquinone, natural antioxidants, for example the natural polyphenols, such as apigenin, resveratrol, ascorbic acid and vitamin C, vitamin E (or alpha-tocopherol), such as IRGANOX® E 201 CIBA Specialty Chemicals, and also by other means if necessary. The break may also optionally be triggered by contact with another fluid, such as another injected fluid, a formation fluid, or a produced fluid such as an acid or basic preflush that will change the pH of the fluid and therefore change the kinetics of the oxidizer decomposition as well as the effect of the delay agent. Injecting another fluid to promote the break is not normally desirable because of potential costs and complexity, but is within the scope of the Invention. The internal breaking effect occurs whether or not a filter cake is also formed by the addition of a fluid loss additive; the breaker may also contribute to degradation of the filter cake.

Suitable oxidizing agents include peroxysulfuric acid; persulfates such as ammonium persulfate, sodium persulfate, and potassium persulfate; peroxides such as hydrogen peroxide, t-butylhydroperoxide, methyl ethyl ketone peroxide, cumene hydroperoxide, benzoyl peroxide, acetone peroxide, methyl ethyl ketone peroxide, 2,2-bis(tert-butylperoxy)butane, pinane hydroperoxide, bis[1-(tert-butylperoxy)-1-methylethyl]benzene, 2,5-bis(tert-butylperoxy)-2,5-dimethylhexane, tert-butyl peroxide, tert-butyl peroxybenzoate, lauroyl peroxide, and dicumyl peroxide; bromates such as sodium bromate and potassium bromate; iodates such as sodium iodate and potassium iodate; periodates such as sodium periodate and potassium periodate; permanganates such as potassium permanganate; chlorites such as sodium chlorite; hyperchlorites such as sodium hyperchlorite; peresters such as tert-butyl peracetate; peracids such as peracetic acid; azo compounds such as azobisisobutyronitrile (AIBN), 2,2′-azobis(2-methylpropionitrile), 1,1′-azobis(cyclohexanecarbonitrile), 4,4′-azobis(4-cyanovaleric acid), and, for example, those sold under the VAZO trade mark by DuPont such as Vazo® 52, Vazo® 64, Vazo® 67, Vazo® 88, Vazo® 56 WSP, Vazo® 56 WSW, and Vazo® 68 WSP; perborates such as sodium perborate; percarbonates; and perphosphates.

Bromates, e.g., sodium bromate, if used alone, can degrade the gel only if the fluid is at relatively high temperatures, such as above about 121.1° C. (250° F.) (the gel is very stable with sodium bromate at 175° F.). No delay was observed when breaking occurred. However, it has been found that the bromates will degrade the gel at lower temperatures when used with a breaking activator. Useful breaking activators include sulfur containing compounds which are also capable of oxidation or reduction. Some specific useful sulfur containing breaking activators are bisulfites, persulfates, and thiosulfates. Another useful breaking activator is an aldehyde such as glutaraldehyde, glucose and the like. Preferred breaking activators include sodium thiosulfate, sodium persulfate and glutaraldehyde.

Without wishing to be bound by theory, it is believed possible that the mechanism for the activation of the bromate salt may be oxidation, reduction, and/or formation of an acid by the breaking activator, which breaks down the bromate salt, allowing it to more effectively break the gel.

In some cases, the viscosity of the fluid may actually initially increase after the addition of the breaking activator; however, such increase is transitional, and reduction in viscosity is later seen. One example of this pattern is seen with metabisulfites and bisulfite breaking activators, which when used with a bromate breaker may initially cause an increase in viscosity, but still cause a complete break not seen with use of only a bromate breaker.

The breaking time may be controlled by selection of the amount and type of breaking activator to be added to the fluid. Useful amounts of breaking activators depend upon the specific activator selected, and the specific breaking agent, but typically range from about 0.1% to about 5%, based on total percentage of solids in the fluid. Time of break is generally reduced at higher percentages. Temperatures also affect the time required for a complete break. One skilled in the art can, by review of the examples and reasonable experimentation, determine what ranges are useful for the time of break desired in the operational temperature range.

Should it be desirable for the breakers or the breaking activators to be coated to delay breaking action, the coating can be done by any known process. Two main types of coating process, top spray and bottom spray, are characterized by the location of the spray nozzle at the bottom or the top of a fluidized bed of solid particles. The nozzle sprays an atomized flow of coating solution while the particles are suspended in the fluidizing air stream that carries the particles past the spray nozzle. The particles then collide with the atomized coating material as they are carried away from the nozzle in a cyclic flow. The temperature of the fluidizing air is set to evaporate solution or suspension liquid media or solidify the coating material shortly after colliding with the particles. The solidified coating materials will cover the particles gradually. This process is continued until each particle is coated uniformly to the desired coating thickness.

The properties of such coated particles can be tuned with the coating formulation, processing conditions, and layering with different coating materials. The choice of material will depend on a variety of factors such as the physical and chemical properties of the material being employed. Coating material can be from one of these categories: aqueous and organic solutions, dispersions, and hot melts. Non-limiting examples include acrylics, halocarbon, polyvinyl alcohol, Aquacoat® aqueous dispersions, hydrocarbon resins, polyvinyl chloride, Aquateric® enteric coatings, HPC, polyvinylacetate phthalate, HPMC, polyvinylidene chloride, HPMCP, proteins, Kynar®, fluoroplastics, rubber (natural or synthetic), caseinates, maltodextrins, shellac, chlorinated rubber, silicone, Coateric® coatings, microcrystalline wax, starches, coating butters, milk solids, stearines, Daran® latex, molasses, sucrose, dextrins, nylon, surfactants, Opadry® coating systems, Surelease® coating systems, enterics, Paraffin wax, Teflon® fluorocarbons, Eudragits® polymethacrylates, phenolics, waxes, ethoxylated vinyl alcohol, vinyl alcohol copolymer, polylactides, zein, fats, polyamino acids, fatty acids, polyethylene gelatin, polyethylene glycol, glycerides, polyvinyl acetate, vegetable gums and polyvinyl pyrrolidone.

The invention is particularly suited for use with polymer free fluids. The invention is especially useful in gravel packing and the like, where near-wellbore damage is often a particularly serious problem. The invention makes it possible to treat wells previously eliminated as candidates due to the low fluid efficiency (high leak-off) that would have been expected. The oxidative internal breakers may be used as an alternative to fluid loss additives, especially when filter cakes are undesirable; instead of minimizing fluid loss, the fluid loss may be accepted and the leaked-off fluid broken. Viscosified fluids containing oxidative internal breakers may also function as a self-destructing diverting agents. They may also be used in kill pills, which can be difficult to break because mechanisms often available for breaking (such as crushing of encapsulated materials, or later addition of another component) cannot be used with kill pills.

In treatments that typically include multiple stages, such as most hydraulic fracturing, acid fracturing, frac-packing, and gravel packing embodiments, the oxidative internal breaker and breaking activator may be added in the pad, throughout the treatment or to only some of the stages, such as some of the proppant, gravel, acid, or diversion stages. The oxidative internal breakers and breaking activators are particularly useful in hydraulic fracturing, frac-packing, and gravel packing because mechanical removal methods are impossible and methods involving contacting the additive with an additional fluid are not always practical. The compositions and methods of the invention are also particularly useful in cases where it is desirable to allow a certain amount of treatment fluid to enter the formation, for example for the purpose of altering formation wettability or oil or water saturation.

Treatment fluids used with the compositions and methods of the invention typically also contain other materials such as demulsifiers, corrosion inhibitors, friction reducers, clay stabilizers, scale inhibitors, biocides, breaker activators, mutual solvents, surfactants, anti-foam agents, defoamers, viscosity stabilizers, iron control agents, diverters, emulsifiers, foamers, oxygen scavengers, pH control agents, buffers, and the like. Compatibility of oxidative internal breakers with such additives should be checked in the laboratory. The treatments of the Invention are conducted normally; the treatment fluid and additives are transported to the site, mixed, stored, and pumped in the usual ways for the respective chemicals. When Resin Coated Proppants (RCP's) are used, testing should be done to ensure that the RCP's and oxidative internal breakers and enhanced oxidative destabilizing systems are compatible and that neither interferes with the performance of the other; conventional natural and synthetic proppants and gravels may normally be used without testing.

The invention is carried out by considering information about the well, the formation, the fluids and additives available, and criteria for a successful treatment, and preparing an optimized plan for maximizing treatment performance according to the data and the criteria. This is usually done by analyzing the well using treatment design and evaluation software; for example, in hydraulic fracturing software, pressure gradients are combined with fracture length and height evolution algorithms, complete leak-off information, and the effects of multiple fluid injections and their temperature changes.

The optimal concentration of the oxidative internal breaker can be determined by choosing the breaking time and rate and measuring the break with samples of the intended fluids under the intended formation conditions. The preferred concentration of oxidative internal breakers is from about 0.005 weight % to about 20 weight %, more preferred is in the range of about 0.01 weight % to about 10 weight %, and most preferred is in the range of about 0.1 weight % to about 5 weight %. (It should be understood that throughout this specification, when we list or describe a concentration or amount range as being useful, or suitable, or the like, we intend that any and every concentration within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term “about” (unless already expressly so modified) and then read again as not so modified unless otherwise stated in context. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when we express a certain range, even if we explicitly identify or refer to only a few specific data points within the range, or even to no data points within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.) Measurement of breaking, and prediction and control of breaking, are familiar to those of ordinary skill in the arts of well stimulation and sand control.

If fluid loss additives are used, it is preferable, although not necessary, to use completely degradable fluid loss additives. Particularly desirable FLA's would be the “internal filter cake/matrix breaker” materials disclosed in copending U.S. patent application Ser. No. 11/532,553, entitled “Internal Breaker for Oilfield Treatments,” inventors Jesse Lee, Philip Sullivan, Erik Nelson, Yiyan Chen, Carlos Abad, Belgin Baser, and Lijun Lin, filed Sep. 18, 2006. When the pad and the fracture fluid are polymer-free and any fluid loss additive is fully degradable, neither the near-wellbore formation nor the proppant bed left in the fracture after the job contains deleterious polymers or solids, as would be the case if the fracture fluid contained any polymer or if the fluid loss additive was not fully degradable. Therefore fracture conductivity is high and skin is low.

Any non-polymeric fluid, for example VES based fluid, that is compatible with the formation, the formation fluids, and the other components of the fluid, can be used in the Invention. Particularly effective non-limiting examples of fluids are those described in U.S. Pat. Nos. 5,551,516; 5,964,295; 5,979,555; 5,979,557; 6,140,277; 6,435,277; and 6,258,859, all of which are hereby incorporated by reference. Vesicle-based fluids may be used, such as those described in U.S. Pat. No. 6,509,301, also hereby incorporated herein by reference.

In some cases, a certain amount of leak-off is desired, for example so that a tip screen-out occurs in fracturing, a condition in which the proppant forms a bridge, preferably at the end of the fracture away from the wellbore, stopping the lengthening of the fracture and resulting in a subsequent increase in the fracture width. For example, hydraulic fracturing followed by gravel-packing in a single operation, sometimes called a frac-pac, fracpac, frac pac, frac and pac, or StimPac, sometimes with a deliberate tip screen-out to generate a short wide fracture, is usually performed in relatively high permeability formations for sand-control purposes. However, such operations are sometimes performed in low permeability formations, occasionally for sand control, but also for other reasons, for example to bypass permeability damage near the wellbore caused by scaling or to improve upon poor communication between the wellbore and the formation or a previous fracture, or in formations in which perforating creates damaging fines, or for other reasons. Such jobs designed to generate short wide fractures may also be performed without subsequent gravel-packing when sand control is not an issue. The methods of the present Invention can be used in any of these cases (fracturing followed by gravel packing and/or fracturing for short wide fractures, in either case with or without deliberate tip screen-out).

The acid used in the matrix acidizing and acid fracturing methods of this Invention can be any acid used in acid fracturing, including gelled, self-diverting, and delayed acids. Commonly used, but not limiting, acids are hydrochloric, hydrofluoric, fluoroboric, acetic, and formic acids and mixtures thereof, and those acids in the form of oil external emulsions (for reaction rate retardation), or oil internal emulsions (for hydrocarbon solvency). The acids can contain additives such as corrosion inhibitors and chelants used to help dissolve rock components and keep them in solution. Gelled, self-diverting, and delayed acids can be gelled with suitable VES's. Some oxidative internal breakers may not be compatible with acid, or with strong acid, and laboratory tests should be performed to determine compatibility.

Although in conventional propped fracturing the most common way to control fluid loss is to build an impermeable or reduced-permeability filtercake on the fracture walls (faces), in acid fracturing, especially with a low viscosity ungelled acid, pad viscosity is important for fluid loss control. On the other hand, if the acid is viscosified with a VES system, then if the VES has higher low-shear viscosity than high-shear viscosity, which is common, then as the VES leaks off a short distance into the formation, the flow rate decreases, the shear rate therefore decreases, and the fluid becomes more viscous. Such effects can reduce low viscosity ungelled acid leak-off better than a wallbuilding system that dissolves or decomposes in acid. In these cases, an oxidative internal breaker would be particularly suitable in the pad. This allows acid treatment a certain selected depth into the formation and the acid then performs the very desirable function of diverting subsequent acid. Similarly, some oxidative internal breakers may be used with viscoelastic diverting acids, which are acids containing certain viscoelastic surfactants, such that the fluid has low viscosity as formulated and injected, but increases in viscosity as the acid reacts with the formation, such as a carbonate. Examples of such systems were described in U.S. Pat. Nos. 6,399,546, 6,667,280, and 7,028,775 and U.S. Patent Application No. 2003-0119680, all hereby incorporated by reference.

Sometimes acid fracturing is performed with a series of alternating pad, acid, pad, acid, etc. stages in order to optimize coverage. The first non-acidic pad initiates a fracture for the first acid stage to follow. That first acid stage etches a portion of the fracture face. Subsequent stages of pad and acid repeat the process until the designed treatment volumes have been injected and the desired fracture has been created. In the past, this process has always used a gelled pad, such as one containing a viscoelastic surfactant system. The oxidative internal breaker of the Invention may be used in at least the first pad and sometimes in all the pad stages. Similarly, matrix acidizing may be performed with alternating stages of acid and another fluid, such as a diverter, some or all of which may be viscosified; the oxidative internal breaker of the Invention may be included in some or all of either the acid or the other fluid to break a viscosifier.

The oxidative internal breakers of the invention may be added to a wellbore fluid by metering them in to the base water fluid as a concentrated liquid. If the material is received as an emulsion, dispersion, or slurry, it can be stored in that form and used in that form directly. If it is received in dry form (for example as a solid dispersible powder of fine particles or as a dry emulsion) the particles can be pre-dispersed in water or brine as required and metered in as a liquid stream, or alternatively they may be added as solids to the base fluid stream.

The reactivity of a given oxidative internal breaker at a particular temperature and in contact with a viscosified fluid or fluids of a particular composition (for example pH and the concentration and nature of other components, especially electrolytes), is readily determined by a simple experiment: exposing the fluid or fluids to the oxidative internal breaker under treatment conditions and monitoring the viscosity.

Although the oxidative internal breakers of this Invention may be used with VES's made with any type of surfactant, or mixtures of surfactants, with or without one or more co-surfactants, and with or without other additives intended to stabilize or modify the properties of the micelles or vesicles (such as buffers, shear recovery additives, salts, and rheology boosters). Preferred VES's are cationic, anionic, amphoteric, and zwitterionic. Suitable VES's, for example, are described in the following U.S. patents, all of which are hereby incorporated in their entirety: U.S. Pat. Nos. 5,964,295; 5,979,557; 6,306,800; 6,637,517; and 6,258,859. The viscoelastic surfactant may be, for example, of the following formulae: R-Z, where R is the hydrophobic tail of the surfactant, which is a fully or partially saturated, linear or branched hydrocarbon chain of at least 14 carbon atoms and Z is the head group of the surfactant which may be for example —NR₁R₂R₃ ⁺, —SO₃ ⁻, —COO⁻ or, in the case where the surfactant is zwitterionic, —N⁺(R₁)(R₂)R₃—COO⁻ where R₁, R₂ and R₃ are each independently hydrogen or a fully or partially saturated, linear or branched, aliphatic chain of at least one carbon atom; and where R₁ or R₂ may comprise a hydroxyl terminal group.

Cleavable viscoelastic surfactants, for example of the following formula, may be used, as disclosed in International Patent Application WO02/064945: R—X—Y-Z, where R is the hydrophobic tail of the surfactant, which is a fully or partially saturated, linear or branched hydrocarbon chain of at least 18 carbon atoms, X is the cleavable or degradable group of the surfactant which is an acetal, amide, ether or ester bond, Y is a spacer group which is a short saturated or partially saturated hydrocarbon chain of n carbon atoms where n is at least equal to 1, preferably 2 and, when n is equal to or greater than 3, the chain may be a straight or branched saturated or partially saturated chain, and Z is the head group of the surfactant which can NR₁R₂R₃ ⁺, —SO₃ ⁻, —COO⁻ or, in the case where the surfactant is zwitterionic, —N⁺(R₁R₂R₃—COO⁻) where R₁, R₂ and R₃ are each independently hydrogen or a fully or partially saturated, linear or branched, aliphatic chain of at least one carbon atom, possibly comprising a hydroxyl terminal group. Due to the presence of the cleavable or degradable group, cleavable surfactants are able to degrade under downhole conditions.

A nonlimiting example of a suitable cationic viscoelastic surfactant useful for the implementation of the Invention is N-erucyl-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride. Nonlimiting examples of some suitable anionic viscoelastic surfactants useful for the implementation of the Invention are monocarboxylates RCOO⁻ such as oleate where R is C₁₇H₃₃ or di- or oligomeric carboxylates such as those disclosed in International Patent Application WO 02/11874.

The oxidizing agents and enhanced oxidative destabilization of this Invention have been found to be particularly useful breakers when used with several types of zwitterionic surfactants. In general, suitable zwitterionic surfactants have the formula: RCONH—(CH₂)_(a)(CH₂CH₂O)_(m)(CH₂)_(b)—N⁺(CH₃)₂—(CH₂)_(a′)(CH₂CH₂O)_(m′)(CH₂)_(b′)COO⁻ in which R is an alkyl group that contains from about 11 to about 23 carbon atoms which may be branched or straight chained and which may be saturated or unsaturated; a, b, a′, and b′ are each from 0 to 10 and m and m′ are each from 0 to 13; a and b are each 1 or 2 if m is not 0 and (a+b) is from 2 to about 10 if m is 0; a′ and b′ are each 1 or 2 when m′ is not 0 and (a′+b′) is from 1 to about 5 if m is 0; (m+m′) is from 0 to about 14; and CH₂CH₂O may also be oriented as OCH₂CH₂. Preferred surfactants are betaines and amidoamine oxides.

Two examples of betaines are oleylamidopropyl dimethyl betaine and erucylamidopropyl dimethyl betaine. Oleylamidopropyl dimethyl betaine contains an oleyl acid amide group (including a C₁₇H₃₃ alkene tail group); erucylamidopropyl dimethyl betaine contains an erucic acid amide group (having a C₂₁H₄₁ tail group). Betaine surfactants, and others that are suitable, are described in U.S. Pat. No. 6,258,859.

Although the invention has been described throughout using the term “VES”, or “viscoelastic surfactant” to describe the non-polymeric viscosified aqueous fluid, any non-polymeric material may be used to viscosify the aqueous fluid provided that the requirements described herein for such a fluid are met, for example the required viscosity, stability, compatibility, and lack of damage to the wellbore, formation or fracture face. Examples, without regard to whether they form, or are described as forming, vesicles or viscoelastic fluids, include, but are not limited to, those viscosifiers described in U.S. Pat. No. 6,035,936 and in GB application No. 2,366,307A.

Also optionally, fracturing fluids may contain materials designed to assist in proppant transport and/or to limit proppant flowback after the fracturing operation is complete by forming a porous pack in the fracture zone. Such materials can be any known in the art, such as are available from Schlumberger under the tradename PropNET® (for example see U.S. Pat. No. 5,501,275). Exemplary proppant flowback inhibitors include fibers or platelets of novoloid or novoloid-type polymers (U.S. Pat. No. 5,782,300).

The choice of oxidative internal breaker is based primarily on the desired time before the delayed break, which will depend upon the choice and concentration of VES and the temperature, and may depend upon the size of the job, the nature of the job, and other factors known to those of ordinary skill in the art. Similarly, appropriate delay agents or accelerating agents and their concentrations may be determined by simple laboratory experiments, for example mixing all the components, heating to the job temperature, and monitoring the viscosity. A requirement is compatibility of the water with the VES system and with the oxidative internal breaker. The system comprising an oxidative internal breaker also works with VES systems that contain co-surfactants or other additives commonly included in oilfield treatment fluids. Again, a requirement is compatibility of the oxidative internal breaker, the VES system, and the other components. The fluid containing an oxidative internal breaker may be batch-mixed or mixed on-the-fly.

Any additives normally used in such treatments may be included, again provided that they are compatible with the other components and the desired results of the treatment. Such additives can include, but are not limited to, corrosion inhibitors, delay agents, biocides, buffers, fluid loss additives, etc. The wellbores treated can be vertical, deviated or horizontal. They can be completed with casing and perforations or open hole.

In gravel packing, or combined fracturing and gravel packing, it is within the scope of the Invention to apply the compositions and methods of the Invention to treatments that are done with or without a screen. Although treatments are normally done to promote hydrocarbon production, it is within the scope of the Invention to use the compositions and methods of the invention in wells intended for the production of other fluids such as carbon dioxide, water or brine, or in injection wells. Although we have described the Invention in terms of unfoamed fluids, fluids foamed or energized (for example with nitrogen or carbon dioxide or mixtures thereof) may be used. Adjustment of the appropriate concentrations due to any changes in the fluid properties (or other parameters, such as proppant concentration) consequent to foaming would be made.

EXAMPLES

Base Fluids

All fluids were evaluated in a Fann 50 Rheometer or Bohlin Rheometer. This instrument requires about 15-20 minutes to reach temperature, so that the early portion of the data reflects heating to the final temperature. The instrument sometimes showed small regular fluctuations around the intended temperature, so small oscillations in the observed viscosities in some figures reflects that occurrence. A standard procedure is used for the Fann50 measurements, where the viscosity is measured at a shear rate of 100 s⁻¹ with ramps down to 75 s⁻¹, 50 s⁻¹ and 25 s⁻¹ every 15 min. A heating time of 15 or 30 min was applied for the fluid to reach the test temperature. More accurate viscosity measurements were obtained on the Bohlin rheometers over a shear rate range between 0.01 s⁻¹ and 100 s⁻¹. Note that fluctuations in viscosities obtained on Bohlin rheometers are generally signatures of very low, water-like viscosities, where the equipment limitations are reached.

Experiments were performed in which a viscoelastic fluid was heated to and held, at test temperatures (there are several temperatures given in the examples), with and without breakers and other additives as noted.

Example 1 Sodium Bromate+Sodium Thiosulfate in 2 wt % KCl Brine at 93.3° C. (200° F.)

This example demonstrates that sodium thiosulfate acts as an activator for sodium bromate to break VES fluid, allowing breaking to occur at relatively low temperatures. FIG. 1 shows a plot of viscosity at 93.3° C. (200° F.) as a function of time for VES fluids containing 4 vol % BET-E-40, 2 wt % KCl, 1 vol % 2-butoxyethanol. The plot designated (a) shows VES with no other additive; (b) shows a similar plot of VES fluid with either 1 wt % sodium bromate or 1 wt % sodium thiosulfate pentahydrate; and (c) shows a similar plot with 1% sodium bromate and 2 wt % or 0.5 wt % sodium thiosulfate pentahydrate. This figure demonstrates that when either sodium bromate or sodium thiosulfate alone is added to the VES fluid, minimal viscosity change is observed compared with that for the base fluid. However, when both the bromate and thiosulfate salts are mixed together with the fluid, complete viscosity reduction occurs after several hours. The fluid stability is well maintained before it breaks to yield a water-like consistency. In addition, FIG. 1 (c) demonstrates that the break time can be controlled by varying the breaker concentration at 93.3° C. (200° F.). Using a smaller amount of breaker allows the breaking to occur at a later time.

FIG. 2 illustrates that the above observed breaking profile also applies to viscosities at low shear rates. Low shear viscosities affect initial sand suspension properties and flow initiation pressure during the cleanup. Fluid samples for this experiment were taken from a bottle aged at 93.3° C. (200° F.) in an oven. Visual inspection of the fluid confirmed the sudden viscosity reduction.

Example 2 Sodium Bromate+Sodium Thiosulfate in 2 wt % KCl Brine at 79.4° C. (175° F.)

FIG. 3 illustrates that sodium thiosulfate can activate the reaction of sodium bromate at even lower temperatures of 79.4° C. (175° F.). Compared with FIG. 1( c), FIG. 3( c) shows that the break time not only can be controlled by variation of the concentration of the activator, and/or breaker, but also by the temperature. Decreasing the fluid temperature to 175° F. leads to increased delay time before the breaking occurs.

Example 3 Sodium Bromate+Sodium Thiosulfate in NaBr Brine at 93.3° C. (200° F.)

This example shows that the unique chemistry of combining sodium bromate and sodium thiosulfate offers well controlled breaking of VES fluids prepared in heavy brines. In this example, experiments were carried out in sodium bromide brine with a density of 1.427 g/ml (11.9 lbm/gal). The base fluid remains stable during the test time frame of 14 hours as shown in FIG. 4 (a). Similar to the data described in Example 1 for unbrined VES fluid, sodium bromate or sodium thiosulfate alone can not break the brined VES fluid. FIG. 4( c) illustrates that when these two salts are both present, complete breaking occurs with hours of delay time.

FIG. 5 shows that the breaking may also be observed at low shear rates, similar to the breaking in 2% KCl brine.

Example 4 Sodium Bromate+Sodium Thiosulfate in CaCl₂ Brine at 93.3° C. (200° F.)

FIGS. 6( a) and 6(b) show that, in heavy CaCl₂ brine, adding sodium bromate to the base VES fluid doesn't result in viscosity reduction when compared with the base fluid. This is the same observation that is made in KCl and NaBr brines, as described in previous examples. The addition of both sodium bromate and sodium thiosulfate, on the other hand, leads to almost immediate breaking once the fluid reaches the test temperature of 200° F. The fast breaking may be attributed to the low pH nature of the CaCl₂ brine that further enhances the reactivity of sodium bromate.

Example 5 Potassium Bromate+Sodium Thiosulfate in 2 wt % KCl Brine at 93.3° C. (200° F.)

Potassium bromate was studied under similar conditions as those described for the sodium bromate. The potassium salt's performance is found to be comparable to that for sodium bromate. The results can be seen in FIGS. 7( a) to 7(c). The change of the counter cation thus does not have effect on the bromate reactivity when used together with sodium thiosulfate.

Example 6 Sodium Bromate+Sodium Thiosulfate with ClearFRAC® XT

The composition of Example 1, i.e., sodium bromate and sodium thiosulfate combination was also tested in ClearFRAC® XT fluids, and provided controlled delay in breaking. The presence of rheology modifiers in ClearFRAC® XT did not affect the break time.

Examples 7-11 show that some chemicals other than thiosulfate salt can be also used to trigger the reaction of sodium bromate to break VES fluids.

Example 7 Sodium Bromate+Glutaraldehyde in KCl and NaBr Brines

Glutaraldehyde was found to assist the breaking of VES fluids with sodium bromate. It is likely that oxidization of the aldehyde generates acidic species that enhances the reactivity of bromate salt. FIGS. 8( a) and 8(b) exhibit the rheology of a VES fluid with 0.5% glutaraldehyde and 1% sodium bromate. It can be seen that delayed viscosity reduction is achieved, and that the delay time decreases when temperature is increased. It should be noted that the viscosity reduction is rather gradual when compared with the viscosity reduction rate when sodium thiosulfate is present as the breaker activator When the same formulation was tested in NaBr brine with a density of 1.427 g/mL (11.9 lbm/gal), the fluid did not break within 50 hours. Only when the glutaraldehyde concentration was increased from 0.5 wt % to 0.75 wt % was a slight viscosity reduction observed. This behavior is in contrast to that of sodium thiosulfate, the effectiveness of which as a breaker activator is not significantly affected when the brine system is changed from 2 wt % KCl to heavy NaBr.

Example 8 Sodium Bromate+Sodium Persulfate in KCl Brine

Sodium persulfate is also an oxidizer. When used together with sodium bromate, viscosity reduction is observed as shown in FIG. 9. Similar to glutaraldehyde, sodium persulfate also results in a more gradual viscosity reduction. The decomposition of sodium persulfate in water also lowers the fluid pH value.

Example 9 Sodium Bromate+Sodium Tetrathionate in KCl Brine

Sodium bromate+sodium tetrathionate were tested in a KCl brine fluid. Unlike sodium persulfate, sodium tetrathionate is a strong reducing agent. When used with sodium bromate, the tetrathionate salt is also found to result in breaking of VES gels (see FIG. 10.) It should be noted that sodium tetrathionate alone can act as a delayed breaker as well. But with the identical amount of 0.5 wt % of the tetrathionate salt, the breaking occurs faster when sodium bromate is also present.

Comparative Example C1 Sodium Chlorate+Sodium Thiosulfate in KCl Brine

Bottle tests were carried out to investigate whether thiosulfate salt could also act as a breaker aid for sodium chlorate. Two fluids A and B, 25 mL for each, were prepared and placed into closed bottles, which then were heated in an oven to reach a constant temperature of 200° F. The fluids were prepared according to the following formulations:

Fluid A: 6 vol % BET-E-40, 2 wt % KCl, and 0.5 wt % sodium chlorate;

Fluid B: 6 vol % BET-E-40, 2 wt % KCl, 0.5 wt % sodium chlorate, and 1% sodium thiosulfate pentahydrate.

The samples were periodically removed from the oven and quickly examined. Samples were first shaken well by hand, and the rate of air bubbles rising through the fluid was used to estimate if any viscosity loss occurred. After extensive exposure of both fluids to 200° F. for five days, no apparent reduction in viscosity was detected. Control experiments with sodium bromate in the presence of sodium thiosulfate, on the other hand, showed complete break of the fluid within a much shorter time frame of half of a day. It is therefore concluded that sodium thiosulfate does not act as a breaker aid for chlorate salts.

Comparative Example C2 Ammonium Chloride+Sodium Bromate

It has been reported in the literature that ammonium chloride could catalyze the reaction of sodium bromate under certain reaction conditions. However, FIG. 11 shows that ammonium chloride does not change the reactivity of sodium bromate within the time frame of 14 hours at 93.3° C. (200° F.). This example illustrates that using an organic amine such as ammonium chloride does not activate sodium bromate breaking of VES fluids. As FIG. 11 shows, after 12 hours at 93.3° C. (200° F.), the fluid does not show any degradation.

Comparative Example C3 Sodium Bromate+Tetraethylenepentamine

As FIG. 12 shows tetraethylenepentamine does not change the reactivity of sodium bromate within the time frame of 14 hours at 93.3° C. (200° F.).

Example 10 Sodium Bromate+Glucose in KCl Brine

Glucose contains an aldehyde group and has a benign environmental profile. Viscosity was tested at 107.2° C. (225° F.) over time for VES fluids containing 6 vol % BET-E-40, 2 wt % KCl, and 2 wt % glucose. FIG. 13 shows that sodium bromate caused viscosity reduction after 12 h at 107.2° C. (225° F.). Control experiments were also conducted with glucose in the absence of sodium bromate. FIG. 14 indicates that a small amount of viscosity loss occurred under the same test conditions. The relatively small difference in the rates of viscosity reduction in these two experiments suggests that glucose acted as a breaker aid but as shown, its effect was not as pronounced compared with sodium thiosulfate, the effect of which was described earlier in Examples 1-6.

Since the above rheology tests lasted only 12 hours, bottle tests were then conducted in an oven but at a lower temperature of 93.3° C. (200° F.) to prevent water from boiling. Bottle tests allowed examining the effect of glucose on sodium bromate over a longer term. The reaction presumably took place at a slower rate than it did at 107.2° C. (225° F.), therefore representing a worse case scenario. Two fluids C and D were prepared and examined following the procedure outlined in Example 1. The fluids were prepared according to the following formulations:

Fluid C: 6 vol % BET-E-40, 2 wt % KCl, 1 wt % sodium bromate, 2 wt % glucose;

and Fluid D: 6 vol % BET-E-40, 2 wt % KCl, 2 wt % glucose.

After 6 hours at 93.3° C. (200° F.), both fluids still remained highly viscous, showing no apparent degradation. When the samples were inspected at test time of 30 hours, Fluid C, containing sodium bromate was significantly less viscous, shown by the air bubbles rising much faster. Essentially no change, however, was detected for Fluid D. After the samples were aged for 55 hours, Fluid C was completely broken to water-like consistency whereas Fluid D still exhibited properties similar to those for the initial gelled fluid. This demonstrates that glucose acted as an aid to sodium bromate.

Example 11 Sodium Bromate+Sodium Bisulfite or Metabisulfite

both thiosulfate and tetrathionate salts were provided as examples of sulfur-containing breaker aids for sodium bromate. To expand the list of these activators that contain sulfur, more compounds were tested including sodium bisulfite (NaHSO₃) and metabisulfite (Na₂S₂O₅). The metabisulfite salt, when dissolved in water, turns into bisulfite, therefore the results with these two salts should be very comparable.

Although Fann50 tests did not yield well reproducible rheology data, overall the results pointed to viscosity reduction. Bottle tests conducted in an oven set at 93.3° C. (200° F.), on the other hand, were found to be relatively more representative of the fluid viscosity change. As an example, two fluids E and F were prepared according to the following formulations:

Fluid E: 6 vol % BET-E-40, 2 wt % KCl, 1 wt % sodium bromate, 0.1 wt % sodium bisulfite; and Fluid F: 6 vol % BET-E-40, 2 wt % KCl, 1 wt % sodium bromate, 0.1 wt % sodium metabisulfite. Both fluids exhibited low initial viscosity at 93.3° C. (200° F.) but regained significant viscosity after about six hours, displaying characteristics of the base fluid without any breaker. The fluids then started to degrade very slowly but continuously, rendering water-like consistency after 4 days. The rheogram shown in FIG. 15 is consistent with the changes observed in the bottle tests for the first two days, illustrating viscosity increase or re-gain in the beginning and degradation later.

It should be understood that only a few examples have been shown for the use of tested oxidizers with a specific VES, at specific concentrations, in specific brines, at specific temperatures, and with or without specific accelerators and retarders at specific concentrations. The fact that a specific oxidizer was observed to be suitable or not in a specific case should not be taken as being a general conclusion for that oxidizer. It is believed that all oxidizers will be suitable under certain conditions. As usual, laboratory testing should be done to determine the optimal use parameters for each oxidizer in each fluid at each condition.

The present invention may be embodied in other specific forms without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the invention is, therefore, indicated by the appended claims rather than by the foregoing description. All changes which come within the meaning and range of equivalency of the claims are to be embraced within their scope. Reference throughout this specification to features, advantages, or similar language does not imply that all of the features and advantages that may be realized with the present invention should be or are in any single embodiment of the invention. Rather, language referring to the features and advantages is understood to mean that a specific feature, advantage, or characteristic described in connection with an embodiment is included in at least one embodiment of the present invention. Thus, discussion of the features and advantages, and similar language, throughout this specification may, but do not necessarily, refer to the same embodiment. Furthermore, the described features, advantages, and characteristics of the invention may be combined in any suitable manner in one or more embodiments. 

What is claimed is:
 1. An oilfield treatment composition comprising an aqueous fluid, a non-polymeric viscosifier, about 0.005 to about 20 wt % of a bromate oxidizing agent and about 0.1% to about 5% based on the total percentage of solids in the fluid of a breaking activator for the bromate oxidizing agent, wherein said breaking activator is selected from the group consisting of sodium thiosulfate, glutaraldehyde, sodium persulfate, sodium tetrathionate, glucose, sodium bisulfate, and sodium metabisulfite, and wherein the oilfield treatment composition exhibits a decrease in viscosity at temperatures lower than exhibited in the absence of a breaking activator.
 2. The composition of claim 1 wherein said breaking activator is glucose.
 3. The composition of claim 1 wherein said oxidizing agent comprises sodium bromate or potassium bromate.
 4. The composition of claim 1 further comprising a free radical propagating agent.
 5. The composition of claim 4 wherein said free radical propagating agent is selected from the group consisting of ferrous ion, metabisulfites, reducing sugars, and reducing di-, tri-, oligo- and poly-saccharides.
 6. The composition of claim 1 wherein said non-polymeric viscosifier comprises a viscoelastic surfactant.
 7. The composition of claim 6 wherein said viscoelastic surfactant comprises a zwitterionic surfactant.
 8. The composition of claim 6 wherein said zwitterionic surfactant comprises a betaine.
 9. The composition of claim 6 wherein said viscoelastic surfactant comprises an amine oxide surfactant.
 10. The method of claim 6 wherein said viscoelastic surfactant comprises a partially saturated hydrophobic chain.
 11. A method of breaking an aqueous gel comprising a non-polymeric viscosifier comprising incorporating about 0.005 to about 20 wt % of a bromate salt oxidizing agent and about 0.1% to about 5% based on the total percentage of solids in the fluid of a breaking activator for said oxidizing agent in the gel, wherein said breaking activator is selected from the group consisting of sodium thiosulfate, glutaraldehyde, sodium persulfate, sodium tetrathionate, glucose, sodium bisulfate, and sodium metabisulfite, and reducing a viscosity of the aqueous gel.
 12. The method of claim 11 wherein said breaking activator is glucose.
 13. The method of claim 11 wherein said oxidizing agent comprises sodium bromate or potassium bromate.
 14. The method of claim 11 wherein said fluid includes a brine selected from the group consisting of NaBr, KCl, NaCl, CaBr₂, and CaCl₂.
 15. The oilfield treatment composition of claim 1 wherein the breaking activator is sodium thiosulfate, sodium persulfate, sodium bisulfate, sodium metabisulfite, or combinations thereof.
 16. The oilfield treatment composition of claim 1 wherein the breaking activator is glutaraldehyde, glucose or combinations thereof.
 17. The method of claim 11, wherein the breaking activator is sodium thiosulfate, sodium persulfate, sodium bisulfate, sodium metabisulfite, or combinations thereof.
 18. The method of claim 11, wherein the breaking activator is glutaraldehyde, glucose or combinations thereof. 